There are very large heavy oil reserves in many countries, US, Canada, Venezuela, USSR, Trinidad, Malagasy, Brasil, etc . . . . Conventional primary recovery techniques are unapplicable because the high viscosity of these oils, often in excess of 1000 centipoises, prevents them from flowing freely to the surface. Various other recovery methods are used instead, the application of which is mostly depth limited. For very shallow oil sands, open pit mining methods and separation of the oil from the sand in surface installations are commonly used. For deeper reservoirs, steam injection from the surface is used generally, but its effectiveness is limited in most cases to about a 2500 FT depth. At such depths, heat losses in surface steam lines and in the well bore reduce the steam quality from a maximum of about 0,9 at the surface boiler down to less than 0,5, a value generally insufficient to provide the high heat rate into the reservoir required for an economical oil flow rate.
To overcome this limitation, various attempts have been made to locate the steam boiler downhole, but disposal of the combustion gases produced from inexpensive fuels such as diesel fuel or lease crude has prevented the industrial application of this technique. When these gases are returned to the surface, they constitute a source of atmospheric pollution, and, when they are injected into the reservoir, their acid content and very high temperature promote rapid corrosion of the well, tubing and casing and downhole burner.
The present invention relates to a process for catalytically creating "in situ" a mixture of steam, hydrogen, various permanent gases, and vapors soluble in the heavy oil. Such a mixture is capable of reducing the heavy oil viscosity when in contact with it for extended periods of time in the reservoir. Because the catalytic reaction is reversible, it proceeds at a finite rate which is controllable, as opposed to fuel combustion, which proceeds by a chain reaction of free radicals at an uncontrollable rate. The temperature achievable in those exothermic catalytic reactions is much lower than that of combustion, but it is sufficient to generate steam at a pressure at least equal to that of the heavy oil reservoir. Because the reactions are taking place within the reservoir itself, the steam produced is no longer subjected to very large heat losses between the point at which it is produced and the point at which it is injected. Regardless of depth, the temperature of the catalytic reactions "in situ" can be controlled by adjusting automatically the non-stoichiometric composition of the reactants injected into the catalytic reactor. The quality of the steam injected into the reservoir is no longer dependent on depth. In one of the embodiments, the catalyst is in a fixed bed, packed in the annular space between the casing and tubing of a well drilled nearly horizontally near the base of the heavy oil reservoir.
In another embodiment, the downhole catalytic reactor is a vertical slurry reactor feeding steam, hydrogen, and oil soluble reaction products into a horizontal liner for injection into the heavy oil zone. In that case, the vertical portion of the well is equipped with a large diameter cemented casing and the catalytic reactor is located in the upper part of the heavy oil zone, or in an overlaying shale bed.
In all cases, one of the reactants (steam or oxygen) is supplied to the downhole reactor through a separate feeder tubing, while the other reactant (CO or H2) is supplied via the casing-tubing annulus. In the case of a vertical slurry reactor, the catalyst and suspension liquid are also supplied to the reactor by means of a second feeder tubing, preferably concentric with the first one. The two feeder tubings may also be used intermittently for circulating the spent catalyst slurry to the surface for regeneration or for disposal. Conventional oil field equipment (tubing hanger, multicompletion packers, downhole valves, etc . . . ) are used for the downhole connections to the catalytic reactor and to the injection well.
The horizontal injection well may be drilled into the heavy oil zone itself, or in the underlying aquifer immediately below the water/oil contact. When the lower boundary of the heavy oil zone is a shale layer, the well may be drilled also partly into the shale layer, at or near the boundary contact surface, provided that communication from the well into the heavy oil zone is established through vertical perforations or vertical fractures intersecting the horizontal well and penetrating into the heavy oil zone. The injection well casing or liner may or may not be cemented to the surrounding rock formation.
The products of the catalytic reaction taking place in the downhole reactor include as primary constituents: hydrogen, high quality steam and sometimes oil soluble permanent gases, such as carbon dioxide or methane or oil soluble vapors such as methanol. Minor impurities in the gas injected into the heavy oil zone may include the unconverted reactants (CO, O2). When the heavy oil is contacted by this gaseous mixture, its viscosity is greatly reduced as a result of the following phenomena occuring successively:
heating of the heavy oil by the condensing steam, PA1 swelling of the heavy oil by dissolution of gases (CO2, CH4) and/or soluble vapors (methanol), PA1 hydrogenation of the hot heavy oil by hydrogen catalyzed by the heavy metals (Ni, V, etc . . . ) originally present in the heavy oil and by the clay minerals present in the reservoir rock. This catalytic hydrogenation proceeds at a rate which is determined by heat input provided by condensation of the injected steam into the reservoir.
Pressure in the injection well is maintained at a value as high as possible. Due to the injection pressure, the reservoir connate water is displaced by the injected fluids, by the the heavy oil swelling and by the by-product gases (CH4 for instance) generated by the heavy oil "in situ" hydrogenation.
The heavy oil of reduced viscosity becomes mobile and flows together with the injected steam and gases into the portion of the pore space initially occupied by the displaced connate water thus forming a mobile oil bank which steadily grows around the injection well.
In a preferred embodiment, the injection well also serves alternatively as production well after each period of fluid injection ("huff and puff" mode of operation). In another embodiment a plurality of production wells drilled vertically are located in two parallel rows, one on each side of the horizontal injection well. To facilitate the drainage of the connate water displaced by the injected fluids and the resulting oil bank, the fluids in the production wells are subjected to artificial lift by pumping or gas lift. This increases the total flowing pressure gradients in the reservoir portion of the heavy oil zone located between injection and production wells. Flow communication between wells may also be enhanced by known techniques, such as hydraulic fracturing. Under the combined effects of the injection pressure in the injection well and of the pumping in the production wells, flow is established in the reservoir. At first the flowing fluids at the production wells are composed primarily of connate water and condensed steam. With the steady expansion of the mobile oil bank, oil and gas flow rates into the production wells increase in time to reach a peak. The decline in production is caused by gravity segregation of the live steam and premanent gases towards the upper part of the heavy oil zone and by their break-through into the production wells. The total oil production rate decline may then be retarded by squeezing cement into the top perforations of the production wells which are subject to steam and gas break-through. In this way a greater portion of the heavy oil initially present in the lower part of the reservoir can be swept by the injected fluids and recovered before the oil rate in the production wells become uneconomic.
Recovery of heavy oil in an entire field is achieved by a combination of similar patterns in which each horizontal injection well alternates with at least one row of vertical production wells.
A plurality of horizontal wells operating intermittently in the injection mode and in the production mode may also be used. Well spacing in both cases is determined by the heat rate and temperatures achievable by the steam condensation, such that the hydrogenation reaction with heavy oil can proceed to equilibrium within the life time of the pattern. The orientation of the horizontal wells is preferentially prependicular to the direction of any natural fracture network in the reservoir.
In another embodiment, each row of vertical production wells is replaced by one or several horizontal wells intersecting a series of vertical fractures. The horizontal production wells are preferably parallel to the injection well but located at some vertical distance above the base of the reservoir to reduce water production by water coning in the vertical fractures.